Well treatment fluid compositions and methods of use that include a delayed release percarbonate formulation

ABSTRACT

A well treatment fluid and method of use includes water, at least one hydratable polymer, an optional crosslinking agent, and a delayed release percarbonate formulation effective to reduce initial viscosity of the fluid after a period of time. Also disclosed are processes for fracturing a subterranean formation.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefits of the legally related U.S.Provisional Patent Application Ser. No. 60/979,975 filed Oct. 15, 2007,which is fully incorporated herein by reference.

BACKGROUND

The present disclosure generally relates to well treatment fluidcompositions and methods of use, and more particularly, to welltreatment fluids and methods that include a delayed release percarbonateformulation.

The internal pressure in an oil well forces only about the first 3percent to the surface and 10-20% can be acquired by traditionalpumping. Gaining access to at least part of the remaining oil requiresmore advanced technology. In order to gain access, viscous welltreatment fluids are commonly used in the drilling, completion, andtreatment of subterranean formations penetrated by wellbores. Forexample, hydraulic fracturing is often practiced as a means to enhancerecovery. During hydraulic fracturing, a viscous well treatment fluid isinjected into a well bore under high pressure. Once the naturalreservoir pressures are exceeded, the fracturing fluid initiates afracture in the formation that generally continues to grow duringpumping. As the fracture widens to a suitable width during the course ofthe treatment, a proppant (e.g., sand grains, aluminum pellets, or othermaterial), may then also be added to the fluid. The proppant remains inthe produced fracture to prevent closure of the fracture and to form aconductive channel extending from the well bore into the formation beingtreated once the fracturing fluid is recovered. The treatment designgenerally requires the well treatment fluid to reach a maximum viscosityas it enters the fracture that affects the fracture length and width.The viscosity of most fracturing fluids is generated from water-solublepolysaccharides, such as galactomannans or derivatives thereof.Crosslinking agents, such as borate, titanate, or zirconium ions, arecommonly added to increase the fluid viscosity.

Once a suitable amount of fractures are formed, it is generallydesirable that the fluid viscosity decrease to levels approaching thatof water after the proppant is placed. This allows a portion of thetreating fluid to be recovered without producing excessive amounts ofproppant after the well is opened and returned to production. Therecovery of the fracturing fluid is accomplished by reducing theviscosity of the fluid to a lower value such that it flows naturallyfrom the formation. Incorporating chemical agents, referred to asbreakers or breaking agents, into the fluid can accomplish thisviscosity reduction or conversion. Typically, these agents are eitheroxidants or enzymes that operate to degrade the polymeric gel structure.

Treatment fluids are also utilized in sand control treatments, such asgravel packing. In gravel-packing treatments, a treatment fluid suspendsparticulates (commonly referred to as “gravel particulates”) fordelivery to a desired area in a well bore, e.g., near unconsolidated orweakly-consolidated formation zones, to form a gravel pack to enhancesand control. One common type of gravel-packing operation involvesplacing a sand control screen in the well bore and packing the annulusbetween the screen and the well bore with the gravel particulates of aspecific size to prevent the passage of formation sand. The gravelparticulates act to prevent the formation particulates from occludingthe screen or migrating with the produced hydrocarbons, and the screenacts to prevent the particulates from entering the production tubing.Once the gravel pack is substantially in place, the viscosity of thetreatment fluid may be reduced to allow it to be recovered. In somesituations, fracturing and gravel-packing treatments are combined into asingle treatment (commonly referred to as “frac pack” operations). Insuch “frac pack” operations, the treatments are generally completed witha gravel pack screen assembly in place with the hydraulic fracturingtreatment being pumped through the annular space between the casing andscreen. In this situation, the hydraulic fracturing treatment may end ina tip screen-out condition. In other cases, the fracturing treatment maybe performed prior to installing the screen and placing a gravel pack.

Maintaining sufficient viscosity in these treatment fluids is importantfor a number of reasons. Maintaining sufficient viscosity is importantin fracturing and sand control treatments for particulate transportand/or to create or enhance fracture width. Also, maintaining sufficientviscosity may be important to control and/or reduce fluid-loss into theformation. Moreover, a treatment fluid of a sufficient viscosity may beused to divert the flow of fluids present within a subterraneanformation (e.g., formation fluids, other treatment fluids) to otherportions of the formation, for example, by “plugging” an open spacewithin the formation. At the same time, while maintaining sufficientviscosity of the treatment fluid often is desirable, it also may bedesirable to maintain the viscosity of the treatment fluid in such a waythat the viscosity may be reduced at a particular time for subsequentrecovery of the fluid from the formation. Additionally, the viscosityalso may help determine the open fracture width.

In choosing a suitable breaker, one may consider the onset of theviscosity reduction, i.e., breakage. Viscous well treatment fluids thatbreak prematurely can cause suspended proppant material to settle outbefore being introduced a sufficient distance into the producedfracture. Moreover, premature breaking can result in a less thandesirable fracture width in the formation causing excessive injectionpressures and premature termination of the treatment.

On the other hand, viscous well treatment fluids that break too slowlycan cause slow recovery of the fracturing fluid from the producedfracture, which delays hydrocarbon production. Still further, theproppant can dislodge from the fracture, resulting in at least partialclosing and decreased efficiency of the fracturing operation.Preferably, the fracturing gel should begin to break when the pumpingoperations are concluded. For practical purposes, the gel preferablyshould be completely broken within about 24 hours after completion ofthe fracturing treatment.

In low-temperature wells, enzymatic breaking agents are often used, butthey are relatively expensive in comparison to oxizidizing breakingagents. In shallow wells, percarbonates are often used, but as thedrilling gets deeper percarbonates provide premature breaking and areless preferred.

Accordingly, there is a need in the art for improved breaking agentsthat can be used in various settings, depths, conditions, and oil wellapplications.

BRIEF SUMMARY

Disclosed herein are well treatment compositions and processes for use.In one embodiment, a well treatment fluid comprises water; at least onehydratable polymer; and sodium percarbonate granules having a delayedrelease coating, wherein the delayed release coating is an inorganicmaterial.

In another embodiment, the well treatment fluid comprises water; atleast one hydratable polymer; and sodium percarbonate granules having adelayed release coating, wherein the delayed release coating comprises amixture of styrene acrylate and butyl acrylate

In another embodiment, a process for fracturing a subterranean formationcomprises injecting under pressure an aqueous hydraulic fluid having afirst viscosity into a well bore, wherein the aqueous hydraulic fluidcomprises water; at least one at least one hydratable polymer; andsodium percarbonate granules having a delayed release coating of aninorganic material; forming fractures in the subterranean formation withthe hydraulic fluid at the first viscosity and dissolving the delayedrelease coating to expose the sodium percarbonate to the water after aperiod of time; reacting the sodium percarbonate with the at least onehydratable polymer to decrease the first viscosity to a secondviscosity; and recovering at least a portion of the hydraulic fluidhaving the second viscosity.

The disclosure may be understood more readily by reference to thefollowing detailed description of the various features of the disclosureand the examples included therein.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring now to the figures wherein the like elements are numberedalike:

FIG. 1 graphically illustrates fluid viscosity at 75° F. as a functionof time for various silicate coated and uncoated sodium percarbonategranules, wherein the fluid included crosslinked guar;

FIG. 2 graphically illustrates viscosity at 133° F. as a function oftime comparing silicate coated sodium percarbonate granules and uncoatedsodium percarbonate granules, wherein the fluid included crosslinkedguar;

FIG. 3 graphically illustrates fluid viscosity at 190° F. as a functionof time for various concentrations of silicate coated sodiumpercarbonate granules and uncoated sodium percarbonate granules, whereinthe fluid included crosslinked guar;

FIG. 4 graphically illustrates fluid viscosity at 75° F. as a functionof time for silicate coated sodium percarbonate granules and uncoatedsodium percarbonate granules, wherein the fluid included a copolymer ofacrylic acid and acrylamide;

FIG. 5 graphically illustrates fluid viscosity at 120° F. as a functionof time for silicate coated sodium percarbonate granules and uncoatedsodium percarbonate granules, wherein the fluid included a linear(uncrosslinked)guar gel; and

FIG. 6 graphically illustrates fluid viscosity at 150° F. as a functionof time for silicate coated sodium percarbonate granules and uncoatedsodium percarbonate granules, wherein the fluid included a boroncrosslinked guar gel.

DETAILED DESCRIPTION

The present disclosure is generally directed to well treatment fluidscontaining a delayed release sodium percarbonate formulation for use inoil field applications. As used herein, the term “delayed release”refers to a dissolution profile that retards the release of oxidizingagent into the well treatment fluid. For example, the delayed releasecoatings of the sodium percarbonate granules could provide dissolutiontimes of on the order of a few minutes up to about 5 hours at neutralpHs (i.e., pHs at about 6 to about 8) depending on the intendedapplication. The delayed release sodium percarbonate can be used in thedrilling, completion, treatment of subterranean formations penetrated bywellbores, and the like, at operating temperatures of 0° F. to about400° F.

The well treatment fluid is an aqueous fluid comprising at least onehydratable polymer, an optional crosslinking agent, and the delayedrelease sodium percarbonate formulation. In addition, an optionalproppant can be added to the fluid depending on the intended oil fieldapplication. During operating, the fluid is pumped into a subterraneanformation at a first viscosity and then allowed to break (i.e., effect areduction in viscosity) as the dissolution of the delayed releasecoating thereabout the sodium percarbonate granule. The well treatmentfluid with the reduced viscosity may then be recovered as may bedesired. The intended end use will dictate the viscosities needed forthe fluid, e.g., gel pigs may require a higher viscosity whereas afracturing fluid may require a relatively lower viscosity.

The aqueous base used in the well treatment fluids are not intended tobe limited and may include water, salt water, brine, sea water, and thelike. Generally, the water can be from any source, treated or untreated,provided it does not contain components that may affect the stability ofany of the other components in the well treatment fluid. The pH of theaqueous fluid can be adjusted to render the fluid compatible with thecrosslinking agent. In one embodiment, a pH adjusting material is addedto the aqueous fluid after the addition of the water-soluble polymer tothe aqueous fluid. Typical materials for adjusting the pH are bases,acids, and buffers. For example, sodium bicarbonate, potassiumcarbonate, sodium hydroxide, potassium hydroxide, and sodium carbonateare typical pH adjusting agents. In one embodiment, pH values for thefluid may range from about 5 to about 14. In other embodiments, the pHis from about 7 to about 14, and in still other embodiments, the pH isbetween about 8 to about 12.

Suitable hydratable polymers include those that are capable of forming agel in the presence of a crosslinking agent. Suitable hydratablepolysaccharides include, but are not limited to, galactomannan gums,guars, derived guars, xanthan, diutan, scleroglucan, and derivativesthereof. Specific examples are guar gum, guar gum derivatives, locustbean gum, Karaya gum, and the like. Suitable hydratable polymers mayalso include synthetic polymers, such as polyvinyl alcohol,polyacrylamides, poly-2-amino-2-methyl propane sulfonic acid, andvarious other synthetic polymers and copolymers. Other suitable polymersare known to those skilled in the art. Mixtures of polymers are alsocontemplated.

The amount of hydratable polymer in the fluid is not intended to belimited. Generally, the hydratable polymer may be present in the fluidat concentrations ranging from about 0.10% to about 5.0% by weight ofthe aqueous fluid. A preferred range for the hydratable polymer is about0.20% to about 0.80% by weight.

A suitable crosslinking agent can be any compound that increases theviscosity of the fluid by chemical crosslinking, physical crosslinking,or any other mechanisms. As used herein, the term crosslinking generallyrefers to the formation of a bond between two molecules. For example,suitable crosslinking agents include borates such as boric acid, sodiummetaborate, sodium tetraborate and the like; titanites such as titaniumchelate esters; dialdehydes; zirconium containing compounds; zinc;various mixtures thereof; and the like. Other suitable crosslinkingagents will be well within the skill of those in the art. The selectionof an appropriate crosslinking agent generally depends upon the type oftreatment to be performed and the hydratable polymer to be used. Theamount of the crosslinking agent used also depends upon the wellconditions and the type of treatment to be effected, but is generally inthe range of from about 10 parts per million (ppm) to about 1000 ppm ofmetal ion of the crosslinking agent in the hydratable polymer fluid. Insome applications, the aqueous polymer solution is crosslinkedimmediately upon addition of the crosslinking agent to form a highlyviscous gel. In other applications, the reaction of the crosslinkingagent can be retarded so that viscous gel formation does not occur untilthe desired time.

The hydratable polymer, independently or in combination with thecrosslinking agent, is present in the fluid at concentrations effectiveto provide a first viscosity greater than 1,000 cP at 3.77 see⁻¹.

The delayed release sodium percarbonate formulation is formed fromsodium percarbonate granules. In the present disclosure, the granulesare substantially spherical particles with a typical size distributionin the range of 0.3 to 1.5 millimeters (mm) with a core of sodiumpercarbonate (Na₂CO₃: 1.5H₂O₂) and a delayed release coating. Meshscreens can be used to isolate particular sizes as may be desired fordifferent applications. The sodium percarbonate granules can be coatedwith an inorganic material or a polymeric material depending on theintended application. Suitable inorganic materials include alkali metaland/or alkaline earth metal silicates. Optionally, the sodiumpercarbonate granules may first be coated with sulfate salt, e.g.,sodium sulfate, magnesium sulfate, and the like. The coating themselvesare preferably uniform and homogenous about the sodium percarbonategranules. The function of the coating layer is to protect the sodiumpercarbonate from contact with humidity and/or water present in theenvironment, which enhances the decomposition of the core material.

In one embodiment, the inorganic material is an alkali metal silicate.coated at an amount of 15 to 37 wt. % relative to the sodiumpercarbonate granules, and in still other embodiments, at 22 to 37 wt.%. It has been found that at amounts less than 15 wt. %, the delay inpercarbonate dissolution in a well treatment fluid is minimal attemperatures up to 150° F. A similar result is observed at a silicatewt. % less of than 22 at temperatures of 150 to 180° F. At amountsgreater than 37 wt. %, the particles tend to agglomerate and formclusters. Once the clusters are formed, the coating has a tendency tobreak asymmetrically during well treatment, thereby prematurely exposingthe hydratable polymer to sodium percarbonate leading to oxidativedegradation of the polymer and a reduction in viscosity. Because ofthis, the dissolution profile is very difficult to predict andoftentimes irregular. An exemplary alkali metal silicate is sodium(Na₂SiO₃).

Suitable polymers for providing the delayed release coating includepolystyrenes, polyacrylates, polysiloxanes, and mixtures thereof.

Coating the sodium percarbonate granules generally includes spraying thesodium percarbonate granules with the desired coating material in afluidized bed. A typical silicate based coating would be performed withan ingoing airflow of 120 to 155 cubic meters per hour (m³/h) at atemperature of 110 to 135° C. By way of example, a percarbonate bed of 2to 3 kilograms (kg) at a temperature of 80 to 105° C. was sprayed at arate of 0.5 to 2.5 kilograms per hour (kg/h) with a solution of thecoating diluted to about 30 to about 40% by weight. Typical polymercoatings can be performed with an ingoing airflow of 125 to 140 m³/h ata temperature of 0 to 70° C. By way of example, a percarbonate bed ofabout 3 kg at a temperature of 19 to 55° C. was sprayed with a polymersolution at a rate of 0.2 to 0.7 kg/h. Coating of the sodiumpercarbonate granules can be performed in a AGT 150 fluidized bed systemcommercially available from Glatt (Germany).

The internal stability of sodium percarbonate granules can be followedby analyzing the active oxygen content at intervals by measuring the TAM(Thermal Activity Monitoring) value, wherein the stability increaseswith decreasing TAM value. A good storage life is indicated by a low TAMvalue. For some applications, the TAM value should preferably be belowabout 15 μW/g and in particular below about 10 μW/g for sodiumpercarbonate. The TAM value is a microcalorimetric analysis of theenergy released during storage, measured by means of the TAM® ThermalActivity Monitor from Thermometric AB (Sweden). As the sodiumpercarbonate degrades, it gives off heat. The flow of this heat ismeasured as a TAM value in μW/g.

Well stimulation and completion (treatment) fluid compositions of thepresent disclosure can further comprise other additives. Additives aregenerally included to enhance the stability of the fluid compositionitself to prevent breakdown caused by exposure to oxygen, temperaturechange, trace metals, constituents of water added to the fluidcomposition, to prevent non-optimal cross linking reaction kinetics, toprotect oilfield equipment, and to prevent the growth of bacteria. Thechoice of components used in fluid compositions is dictated to a largeextent by the properties of the hydrocarbon-bearing formation on whichthey are to be used. Such additives can be selected from the groupincluding oils, salts (including organic salts), biocides, corrosioninhibitors and dissolvers, pH modifiers (e.g., acids and bases), metalchelators, metal complexors, antioxidants, wetting agents, polymerstabilizers, clay stabilizers, scale inhibitors and dissolvers, waxinhibitors and dissolvers, asphaltene precipitation inhibitors, waterflow inhibitors, fluid loss additives, chemical grouts, diverters, sandconsolidation chemicals, proppants, permeability modifiers, viscoelasticfluids, gases (e.g., nitrogen and carbon dioxide), foaming agents, andthe like.

The following examples are presented for illustrative purposes only, andare not intended to limit the scope of the invention.

EXAMPLES

In the following examples, sodium percarbonate was commercially obtainedfrom Kemira Kemi AB under the tradename Ecox. Sodium silicate wascommercially obtained at a molar ratio of 3.3±0.2 from Askania (Sweden).Styrene acrylate polymer and butyl acrylate/styrene polymer was obtainedfrom commercial paint manufacturer Beckers (Sweden).

Stability was determined by analyzing the active oxygen content of afreshly prepared sample and comparing it with active oxygen contentafter 2 months. The active oxygen or hydrogen peroxide content wasdetermined by titration with potassium permanganate (0.2 N) in acidicsolution (10% sulphuric acid). A sample of 5 grams (g) was dissolved in75 milliliters (ml) of 10% H₂SO₄ solution. Of this sample, 3 g of thesolution was titrated with KMnO₄ solution using a combined Pt-electrode;a Metrohm 794 Basic Titrino and Metrohm 665 Dosimat.

Dissolution time was analyzed by conductivity, measured with a Cond340i, WTW on 2 g sample in 1 liter (L) of deionized water at 20° C. Thesample was stirred at approximately 750 revolutions per minute (rpm)throughout the measurement. The rate of dissolution is given graphicallyas the time (in minutes) at which 90% of maximum conductivity wasobtained.

Example 1

In this example, sodium percarbonate granules were coated with differenttypes of coating materials at various thicknesses. Dissolution time andstability were measured. Stability was measured as the active oxygencontent (AO) over a 2 month period of time. The results are provided inTable 1.

The active oxygen values provided means for comparing the relativestability between samples. The 24-hour value is a standard uncoatedsodium percarbonate reference value as the uncoated sodium percarbonategranules typically reach a stable value after this period of time.

TABLE 1 Coating Calculated coating Dissolution Initial AO 2 Sample #(analyzed %) (min) AO % month % Control Uncoated (ref) 68 (sec) 32 —Control Uncoated (ref) 51 (sec) 31 — 1 Na₂SiO₃ 10% 33 28 28 2 Na₂SiO₃30% 180 21 21 3 Styrene acrylate 0.9% 23 31 30 4 Styrene acrylate 1.7%68 30 30 5 Butyl acrylate 8% 12 28 26 6 Butyl acrylate 30% 26 21 21 7Styrene acrylate 2% + 175 30 30 butyl acrylate 3%

The dissolution time units for the controls were seconds. The resultsindicate that dissolution time of sodium percarbonate is extended byapplying a coating of a polymeric material or an inorganic material. Asa single coating, the silicate-coated sodium percarbonate granulesexhibited a very good effect on dissolution time at room temperature andalso gave a very stable product. Although the coatings with one type ofpolymer, butyl acrylate, were generally less effective, the combinationof polymers seemed to have a synergistic effect and was very efficienteven with rather thin coatings. The polymer coatings appeared to have apositive effect on the stability as well.

Example 2

In this example, coating stability of sodium silicate-coated sodiumpercarbonate and its degradation capability of guar was analyzed duringfor an oil well pumping simulation. In a 2-L vessel, 1000.0 g ofdeionized water was added to 10.0 g of an anionic carboxymethylhydroxypropyl guar commercially obtained from Hercules, Incorporatedunder the tradename Aqualon Galactasol 651 and stirred for about 30 minat 3000 rpm to form a stock solution. To 175.0 g of the stock solution,0.8 g of a titanium based crosslinker commercially available from E.I.du Pont de Nemours and Company under the tradename Tyzor® 131 was added,stirred at 1500 rpm for about 2 minutes and allowed to gel for about 30minutes. Using a Grace M3500A rotary viscometer equipped with an R1rotor and a B2 bob, the gel was presheared at 75.4 s⁻¹ at a predefinedtemperature for 30 min and then sheared for 30 s at 3.77 s⁻¹ to measurethe initial gel viscosity. Next, a predefined amount of breaker wasadded, and the gel was sheared at 75.4 s⁻¹ for 60 minutes, with30-second breaks at 3.77 s⁻¹ to measure the viscosity after 1, 3, 5, 7,10, 15, 20, 25, 30, 35, 40, 45, 50, 55, and 60 minutes. The parametersfor each test are provided in Table 2.

TABLE 2 BREAKER CONCENTRATION TEMP. (wt % sodium percarbonate actives)(° F.) Na₂SiO₃ (wt %) 1 0.05 75 Uncoated 2 0.5 75 Uncoated 3 0.275 133Uncoated 4 0.05 190 Uncoated 5 0.5 190 Uncoated 6 0.275 75 10 7 0.05 7530 8 0.5 75 30 9 0.275 133 30 10 0.05 190 30 11 0.5 190 30

FIGS. 1-3 graphically illustrate viscosity as a function of time withall of the data for the above samples normalized as a percentage ofinitial viscosity. The room-temperature data as presented in FIG. 1shows that both silicate-coated samples provided excellent stabilityrelative to uncoated sodium percarbonate monitored at the sametemperature. The 30 wt % sodium silicate-coated sodium percarbonategranules exhibited less release as a function of time than did the 10%sodium silicate-coated sodium percarbonate granules. At highertemperatures, however, the percarbonate released more rapidly into thegel as evidenced by the quicker reduction in viscosity and, whenevaluated at 190° F., there is little difference between coated anduncoated samples.

Example 3

In this example, guar polymer degradation in the absence of shear wasstudied for various coated and uncoated sodium percarbonate granules. Ina 2-L vessel, 1,500.0 g deionized water was added to 15.0 g AqualonGalactasol 651 guar polymer and stirred for 30 minutes at 3000 rpm toform a stock solution of the guar polymer. The guar polymer was notcrosslinked. A 300.0 g portion of the stock solution was poured into a400-mL vessel. Half of this (150.0 mL) was poured into a pressurizableaging cell commercially available by Fann Instrument Company and variousamounts of coated and uncoated sodium percarbonate were added as shownin Table 3. The remaining guar polymer solution (150.0 mL) was added tothe cell, which was then sealed and pressurized. The aging cell wasshaken three times to disperse the sodium percarbonate granules andplaced in an oven for a period of time as defined in Table 4. Afterward,viscosity was measured at 3.77 s⁻¹ at 75° F. on a Grace M3500aviscometer equipped with an RF1 rotor and a B2 bob. The temperatures andpressures used were chosen to simulate depths varying between 500 and2500 feet, and the time was varied between 4 and 28 hours. Thetemperature and pressures used to simulate different oil well depths areprovided in Table 3, while Table 4 provides the experimental conditionsand results for each sample.

TABLE 3 DEPTH (ft) TEMP. (° F.) PRESSURE (psi) 500 82 250 2,500 1131,250

TABLE 4 CONCENTRATION VISCOSITY (wt % sodium DEPTH TIME Na₂SiO₃ at 3.77s⁻¹ percarbonate actives) (ft) (h) (wt %) (cP ± 80 cP) 1 0.05 500 4Uncoated 4395 2 0.5 500 4 Uncoated 2996 3 0.05 500 28 Uncoated 3271 40.5 500 28 Uncoated 859 5 0.05 2,500 4 Uncoated 3291 6 0.5 2,500 4Uncoated 1521 7 0.05 2,500 28 Uncoated 1576 8 0.5 2,500 28 Uncoated 9209 0.05 500 4 30 5304 10 0.5 500 4 30 4827 11 0.05 500 28 30 3835 12 0.5500 28 30 2630 13 0.05 2,500 4 30 3375 14 0.5 2,500 4 30 2956 15 0.052,500 28 30 1967 16 0.5 2,500 28 30 947

The results indicate that the 30 wt % sodium silicate-coated sodiumpercarbonate had an interesting profile for degrading the guar. Atshallow depths and shorter times, the coated sodium silicate coatedpercarbonate showed much slower degradation than the uncoated sodiumpercarbonate, but at deeper conditions and longer times it degrades guaras well as uncoated sodium percarbonate. The greater speed of guardegradation results from the increased rate of sodium percarbonatedecomposition at elevated temperatures. This causes pressure to rapidlyrise inside the coating, eventually cracking it from the inside andallowing sodium percarbonate to escape into the guar before the coatingis dissolved. However, the temperature of the guar only slowly risesfrom the surface temperature as it is pumped down hole and subsequentlyheated at the bottom of a well.

Example 4

In this example, the following breakers were evaluated in a 4 pounds per1000 gallons polymer solution (lb/Mgal) at 75° F.: a control withoutbreaker; uncoated sodium percarbonate; sodium percarbonate coated with22 wt % sodium silicate; and sodium percarbonate coated with 28 wt %sodium silicate were evaluated.

The polymer solution was prepared by adding 0.441 grams (g) of anultrahigh molecular weight copolymer of acrylic acid and acrylamidecommercially available under the trade name Callaway A-4330 to 1000 g ofdeionized water. The solution was mixed for 30 minutes at 600 rpm. Thepolymer solution (175 g) was poured into a sample cup and placed under aGrace 3500 viscometer equipped with an R1 rotor and B1 bob. The rotorbegan shearing the fluid at 100 s⁻¹ and the breaker (0.012±0.004 g) wasimmediately added. Viscosity was measured as a function of time for 90minutes.

The results for these experiments are shown in FIG. 4. The viscosity ofthe control sample remains constant over the test time, as does that ofthe fluid treated with the sodium percarbonate that had been coated witha 28 wt % sodium silicate coating. The production sodium percarbonatesample with a 22 wt % coating exhibited no release for the first 20minutes, and then slowly degraded the polymer as evidenced by theviscosity reduction. The uncoated SPC, however, reacted quickly andimmediately degraded the polymer solution. Thus the presence of thesodium silicate coating was effective to delay release of the sodiumpercarbonate. Furthermore, thicker coatings appear to correlate withslower releases of sodium percarbonate into the fluid.

Example 5

In this example, the following breakers were evaluated in a 40 poundsper 1000 gallons (lb/Mgal) linear guar gel solution at 120° F.: acontrol without breaker; uncoated sodium percarbonate; sodiumpercarbonate coated with 22 wt % sodium silicate; and sodiumpercarbonate coated with 28 wt % sodium silicate were evaluated.

The linear guar gel was prepared using a Waring blender attached to arheostat set to 55%. Deionized water (800.0 g) was added to the blender,and then the blender was run on low speed. Next, guar (3.841 g)commercially available under trade name HR71-51D from BenchmarkPerformance Group was added while the blender was stirring and thesolution was blended on low speed for 30 minutes. Finally, the solutionwas allowed to rest for 30 minutes in the absence of shear.

The tests were performed on a Grace 3500 viscometer equipped with an R1rotor and B1 bob. For a test, a portion (175.0 g) of the guar solutionwas poured into the sample cup, which was placed under the viscometer.The breaker (0.104±0.003 g) was added, and then the rotor began shearingthe sample at 511 s⁻¹ while the temperature ramped to 120° F. For eachsample, the viscosity was measured as a function of time for 90 minutes.

FIG. 5 illustrates the results. The uncoated sodium percarbonate causesan immediate and rapid drop in the viscosity of the guar, while the twocoated samples degrade the viscosity more slowly. Furthermore, thesample with 28 wt % sodium silicate coating degrades the guar moreslowly than the production sample with the 22 wt % sodium silicatecoating. The time release coating significantly slows the degradation ofthe linear guar gels relative to the degradation caused by uncoatedsodium percarbonate. Furthermore, thicker coatings appear to correlatewith slower releases of sodium percarbonate into the fluid.

Example 6

In this example, the following breakers were evaluated in 40 pounds per1000 gallons (lb/Mgal) boron crosslinked linear guar gel solution at150° F.: a control without breaker; uncoated sodium percarbonate; sodiumpercarbonate coated with 22 wt % sodium silicate; and sodiumpercarbonate coated with 28 wt % sodium silicate were evaluated.

The boron crosslinked guar gel was prepared using a Waring blenderattached to a rheostat set to 55%. Deionized water (800.0 g) was addedto the blender, and then the blender was run on low speed. Next, guar(3.8425 g) commercially available under the trade name HR71-51D fromBenchmark Performance Group was added while the blender was stirring andthe solution was blended on low speed for 30 minutes. Next, a buffer(0.5 mL) commercially available under the trade name S-166 and a boroncrosslinker (2.4 mL) commercially available under the trade name BX-1from Benchmark Performance Group were added and the blender was run for1 minute. The solution was then allowed to rest for 30 minutes in theabsence of shear.

The tests were conducted on a Grace 5600 viscometer equipped with an R1rotor and B5 bob. For each test, a portion (31.7±1.6 g) of thecrosslinked guar solution was poured into the sample cup, which wasplaced under the viscometer, and then the rotor began shearing thesample at 100 s⁻¹ while the temperature ramped to 150° F. For eachsample, the viscosity was measured as a function of time for 60 minutes.The results are shown in FIG. 6.

As shown, the uncoated sodium percarbonate rapidly degraded theviscosity, and caused a total break after 48 minutes. The sodiumpercarbonate with the 28 wt % sodium silicate coating caused a smalldecrease in the viscosity after 60 minutes, while the production 22 wt %sodium silicate coating resulted in a slightly larger drop in thecrosslinked gel's viscosity over the testing period. Thus, encapsulatingthe sodium percarbonate with sodium silicate has been shown to slow therate of viscosity loss.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to make and use the invention. The patentable scope of the inventionis defined by the claims, and may include other examples that occur tothose skilled in the art. Such other examples are intended to be withinthe scope of the claims if they have structural elements that do notdiffer from the literal language of the claims, or if they includeequivalent structural elements with insubstantial differences from theliteral languages of the claims.

1. A well treatment fluid, comprising: water; at least one hydratable polymer; and sodium percarbonate granules having a delayed release coating, wherein the delayed release coating is an inorganic material.
 2. The well treatment fluid of claim 1, wherein the inorganic material is an alkali metal silicate.
 3. The well treatment fluid of claim 2, further comprising sodium sulfate intermediate the sodium percarbonate and the alkali metal silicate.
 4. The well treatment fluid of claim 2, wherein the alkali metal silicate is in an amount of 15 to 37 weight percent relative to a total weight of the sodium percarbonate and the alkali metal silicate.
 5. The well treatment fluid of claim 2, wherein the alkali metal silicate is in an amount of 22 to 37 weight percent relative to a total weight of the sodium percarbonate and the alkali metal silicate.
 6. The well treatment fluid of claim 1, wherein at least one hydratable polymer comprises a polysaccharide, a polyacrylamide, a polyvinylalcohol, and mixtures thereof.
 7. The well treatment fluid of claim 1, further comprising a crosslinker, wherein the crosslinker comprises a titanate, a borate, a zirconium-containing compound, a dialdehyde, and mixtures thereof.
 8. The well treatment fluid of claim 1, wherein the fluid has a pH from 5 to
 12. 9. The well treatment fluid of claim 1, wherein the sodium percarbonate granules having a delayed release coating are configured to provide a dissolution rate at up to about 3 hours at a neutral pH at about room temperature.
 10. The well treatment fluid of claim 1, further comprising a proppant.
 11. The well treatment fluid of claim 1, wherein the at least one hydratable polymer is a guar gum and/or a guar gum derivative.
 12. A well treatment fluid, comprising: water; at least one hydratable polymer; and sodium percarbonate granules having a delayed release coating, wherein the delayed release coating comprises a mixture of styrene acrylate and butyl acrylate.
 13. A process for fracturing a subterranean formation comprising: injecting under pressure an aqueous hydraulic fluid having a first viscosity into a well bore, wherein the aqueous hydraulic fluid comprises water; at least one at least one hydratable polymer; and sodium percarbonate granules having a delayed release coating of an inorganic material; forming fractures in the subterranean formation with the hydraulic fluid at the first viscosity and dissolving the delayed release coating to expose the sodium percarbonate to the water after a period of time; reacting the sodium percarbonate with the at least one hydratable polymer to decrease the first viscosity to a second viscosity; and recovering at least a portion of the hydraulic fluid having the second viscosity.
 14. The process for fracturing the subterranean formation of claim 13, wherein the aqueous hydraulic fluid further comprises a crosslinker for adjusting the first viscosity of the fluid.
 15. The process for fracturing the subterranean formation of claim 13, wherein the inorganic material is an alkali metal silicate.
 16. The process for fracturing the subterranean formation of claim 13, further comprising adding a proppant to the hydraulic fluid prior to injecting under pressure and in an amount effective to prevent the fractures from closing.
 17. The process for fracturing the subterranean formation of claim 13, wherein the at least one hydratable polymer comprises a polysaccharide, a polyvinyl alcohol, a polyacrylamide, and mixtures thereof.
 18. The process for fracturing the subterranean formation of claim 13, wherein the at least one hydratable polymer is a guar gum or guar gum derivative.
 19. The process for fracturing the subterranean formation of claim 13, wherein dissolving the delayed release coating to expose the sodium percarbonate to the water after the period of time comprises configuring the delayed release coating with a dissolution rate at up to about 3 hours at a neutral pH and about room temperature.
 20. The process for fracturing the subterranean formation of claim 13, wherein the crosslinker comprises a titanate, a borate, a zirconium-containing compound, a dialdehyde, and mixtures thereof.
 21. The process of claim 15, wherein the alkali metal silicate is in an amount of 15 to 37 weight percent relative to a total weight of the sodium percarbonate and the alkali metal silicate.
 22. The process for fracturing the subterranean formation of claim 15, wherein the alkali metal silicate is in an amount of 22 to 37 weight percent relative to a total weight of the sodium percarbonate and the alkali metal silicate.
 23. The process for fracturing the subterranean formation of claim 15, further comprising sodium sulfate intermediate the sodium percarbonate and the alkali metal silicate. 